Stimulation method and system for enhancing oil production

ABSTRACT

A method of recovering in situ hydrocarbons from a subterranean formation includes injecting a volume of fluid with composition comprising 0.01 mass % or more of at least one ketone and 50 mass % or more of water into an injection well completed in the subterranean formation; and producing at least a fraction of the injected volume of fluid and in situ hydrocarbons from the subterranean formation through a production well completed in the subterranean formation. A hydrocarbon recovery system includes an injection apparatus connected to a well formed in a subterranean formation and a storage container in fluid communication with the injection apparatus. The container includes the at least one ketone and water.

BACKGROUND OF THE INVENTION

1. Field of the Invention

The present invention is directed to a stimulation method and system for enhancing oil production.

2. Description of Background Art

Over the years, enormous strides in various oil extraction and oil recovery (also referred to as “oil production”) methods have been achieved, ranging from improved oil recovery methods (also known as IOR), incorporating technologies such as water injection into subterranean oil bearing formations, to enhanced oil recovery (“EOR”) methods, incorporating technologies such as gas injection into subterranean oil bearing formations.

Mature EOR technologies include gas injection based methods, microbial based methods, chemical based methods, and thermal based methods. Thermal methods and gas injection are the two most commonly applied EOR technologies commercially. Thermal methods include technologies such as Steam Assisted Gravity Drainage (SAGD) and Cyclic Steam Stimulation (CSS). Gas injection recovery processes include technologies such as CO₂ injection, nitrogen injection, and hydrocarbon gas injection. Gas injection processes often follow water injection processes, and in some cases water and gas injection are alternated to improve sweep efficiency and mitigate the effects of viscous fingering due to adverse mobility contrasts between the gas and the in-situ oil and gravity override due to density contrasts between the gas and the oil. Such processes are sometimes referred to as water alternating gas injection or WAG.

Attention has also been focused on water-assisted production methods, i.e. introducing “additives” to the injection water (changing the composition of the water) in order to improve or optimize the water flood efficiency. These enhanced oil recovery processes are referred to as chemical floods. Exemplary techniques include: alkali-surfactant-polymer flooding, polymer flooding, surfactant flooding, low-salinity water injection, and combinations thereof. In all these cases, the water composition is modified before injection. For instance, surfactants may be included to reduce interfacial tension between oil in order to mobilize residual oil after water-flooding. Polymer based gels may be added to block preferential water flow through high permeability (thief) zones.

In addition to improved oil recovery methods and enhanced oil recovery methods, other forms of technologies have been applied to improve the economics of oil recovery from challenged resources. Exemplary techniques include: horizontal drilling, artificial lift, and hydraulic fracturing. Horizontal drilling results in increased reservoir contact with the production well. Artificial lift is used to increase the drawdown in the reservoir, allowing the hydrocarbons to more readily flow to a production well. Similar to horizontal wells, hydraulic fracturing is used to create more surface area in close proximity to a high permeability channel in direct communication with a production well, allowing hydrocarbons to more readily flow to a production well. Hydraulic fracturing is a complex process, often with dozens of chemicals added to optimize proppant transport, proppant placement & settling, and wellbore flow. Often high injection rates are required to fracture a subterranean formation effectively. These high rates result in substantial pressure drops through the well due to friction. In order to mitigate this pressure drop, friction reducing chemicals such as polyacrylamide or long-chain polymers are added to the fracturing fluid to mitigate turbulence in the well. Another challenge with hydraulic fracturing is effectively transporting and placing proppant. It is largely accepted that low viscosity fluids create more complex fracture networks with more effective connectivity to the formation, but these fluids cannot effectively transport or place proppant deep in the formation. Therefore, a number of other chemicals are added to the fracture water to assist in proppant transport. In this complex process a variety of chemicals can be injected for various purposes including hydrochloric acid, sodium sulfate, sodium hydroxide, methanol, ethylene glycol monobutyl ether, alcohol ethoxylate, glutaraldehyde, ethanol, petroleum distillate, ammonium acetate, polyacrylamide, sorbitol tetraoleate, surfactants, etc.

The industry is also looking into recovering oil from geologic landscapes that formerly were economically challenged. For instance, ultra-tight permeability reservoirs often referred to as shale reservoirs. These reservoirs can contain hydrocarbons in the oil phase, gas phase or both phases. The hydrocarbons in these reservoirs may or may not actually be contained in shales. In some cases, they are simply contained in very low permeability carbonates, siliciclastics, or combinations thereof. A common attribute among this reservoir class is how they are typically developed. Many ultra-tight systems or shale reservoirs are economically developed using techniques such as horizontal wells and hydraulic fracturing to increase contact of the well with the formation The Bakken formation is one example of such an ultra-tight reservoir or subterranean hydrocarbon bearing formation

Oil production rates from such reservoirs under primary depletion often dramatically decline, resulting in oil rates that are only a small fraction of the initial production rates in a relatively short time. In many cases rates can drop to much less than 10% of the initial production rate within two to three years. Oil recovery is further impeded by large water cuts (that is, the ratio of water produced in comparison to the total volume of liquids produced) during primary depletion, which can range upwards of 80% in some cases.

Many of these reservoirs also tend to have at least some portions of the reservoir which are oil-wet or mixed-wet, where the contact angle between the oil-water interface and the surface of the formation measured through the water phase is greater than 90 degrees. This presents several problems with efficiently recovering oil from the reservoir. First, many of these reservoirs are hydraulically stimulated to maintain pressure, increase their production potential, and open up access to additional parts of the formation; however, this stimulation often injects large volumes of water, which do not readily imbibe into oil-wet or mixed-wet ultra-tight formations. This results in much of the potential drive energy injected into the formation being used to simply reproduce the injected water, rather than oil. Under primary depletion for a given pressure drop in a control volume in the reservoir a volume of fluids will be produced through a production well, which corresponds to the compressibility of the formation and the fluids in the control volume. If a certain subterranean formation has a higher water-cut than another subterranean formation due to the properties of the formations and fluids in the formations than under an equivalent pressure drop, the latter formation will produce more oil, all else being equal.

In many cases, the wettability of a formation influences the recovery factor in that formation. It is well accepted that formations with more affinity for water (i.e., formations that are more water-wet), generally are more conducive to water flooding than comparable formations that have much less affinity to water (i.e., formations that are strongly oil wet). This fact, coupled with the ultra-low permeability found in ultra-tight oil reservoirs in part explains why most ultra-tight oil formations that are largely oil-wet or mixed-wet are currently developed only using primary recovery, unlike many conventional reservoirs, which almost ubiquitously apply IOR or EOR methods.

Currently, some chemicals may be injected along with the hydraulic fracturing fluid, but they are in large part in very low concentrations, and likely have a minimal impact on a vast majority of the formation's wettability. Researchers, using surfactant-based methods, have begun to examine methods of altering wettability in these formations using a number of chemicals. These surfactant-based methods rely heavily on altering the apparent wettability of the earth material by simply bonding with polar or polar-non-polar hydrocarbon components, which are attached to the rock surface. Surfactants, while effective, are also expensive compared to some other chemicals. They also have a propensity to adsorb to the rock surface, which does not necessarily utilize the surfactant most effectively and they have potential to degrade with time, shear, and temperature. Thus, apparent wettability alterations with surfactant can be temporary.

Therefore, there is an industry-wide need for a method of more accurately identifying suitable methods for recovering oil from these formations, and new systems and compositions which maximize the recovery from these formerly challenged reservoirs. In addition, there is a challenge in the industry to improve the predictive capability of hydrocarbon recovery, including finding relations between surface chemistry, wettability, capillary pressure, and relative permeability.

SUMMARY OF THE INVENTION

The present invention is directed to methods of enhancing oil recovery from hydrocarbon bearing subterranean formations where portions of the formation are oil-wet to mixed-wet. The technology also includes methods of modeling formations, new compositions for recovering oil from the formations, and new systems for recovering oil from the formations.

In particular, according to an embodiment of the present invention, the present invention is directed to a method of recovering in situ hydrocarbons from a subterranean formation containing in situ hydrocarbons, the method comprising the steps of: injecting a volume of fluid with composition comprising 0.01 mass % or more of at least one ketone and 50 mass % or more of water into an injection well completed in the subterranean formation; and producing at least a fraction of the injected volume of fluid and in situ hydrocarbons from the subterranean formation through a production well completed in the subterranean formation.

According to another embodiment, the present invention is directed to an in situ hydrocarbon recovery system comprising: a well connected to a subterranean formation containing in situ hydrocarbons; an injection apparatus connected to said well; and at least one storage container in fluid communication with the injection apparatus, wherein said at least one storage container includes at least one ketone and wherein said at least one storage container includes water.

According to a further embodiment, the present invention is directed to a method of altering the wettability of a subterranean formation containing in situ hydrocarbons, the method comprising the steps of: injecting a volume of fluid with a composition comprising 0.01 mass % or more of at least one ketone and 50 mass % or more of water into an injection well completed in the subterranean formation, wherein the subterranean formation is comprised of at least 10 mass % carbonate rock, thereby contacting the carbonate rock of the subterranean formation with at least a fraction of the injected volume of fluid; and permitting the injected volume of fluid to reside for a period of time in the subterranean formation.

According to yet a further embodiment, the present invention is directed to a method of recovering hydrocarbons from a subterranean formation containing in situ hydrocarbons, the method comprising the steps of: building a computational model to simulate injecting a ketone and water into a subterranean formation containing in situ hydrocarbons; making a determination on how to operate an oil recovery process from the subterranean formation based on said computational model; and recovering hydrocarbons from the subterranean formation.

Further scope of applicability of the present invention will become apparent from the detailed description given hereinafter. However, it should be understood that the detailed description and specific examples, while indicating preferred embodiments of the invention, are given by way of illustration only, since various changes and modifications within the spirit and scope of the invention will become apparent to those skilled in the art from this detailed description.

BRIEF DESCRIPTION OF THE DRAWING

The present invention will become more fully understood from the detailed description given below and the accompanying drawings which are given by way of illustration only, and thus are not limitative of the present invention, and wherein:

FIG. 1 is a diagrammatic view of an example of a hydrocarbon bearing subterranean formation to which the present invention is applicable;

FIG. 2 is an illustration to explain oil wet and water wet formations;

FIG. 3 is an illustration to explain tight to ultra-tight hydrocarbon bearing formations;

FIG. 4 is an illustration of stimulating with slugs of chemicals; and

FIG. 5 is a comparison of simulation models.

DETAILED DESCRIPTION OF THE INVENTION

The present invention will now be described with reference to the accompanying drawings.

FIG. 1 is an example of a ketone supply, injection, and production system for hydrocarbon recovery from a hydrocarbon bearing subterranean formation. A well (102) is drilled in a hydrocarbon-bearing subterranean formation (104). Alternatively, an existing well (102) can be utilized. The well (102) can be a single well, operational as both an injection and production well, or alternatively the well can be distinct injection and production wells. The well (102) may be conventional or directionally drilled, thereby reaching the formation (104), as is well known to one having ordinary skill in the art.

The formation (104) can be hydraulically stimulated using conventional hydraulic fracturing methods, thereby creating fractures (106) in the formation. During injection, or during a cyclic injection phase, the production of hydrocarbons is stimulated by injecting via an injection device (108) a volume of fluid through the well (102) and into an influence zone (110). The injectant can include at least water and one or more ketones, which are contained in respective water (112) and ketone (114) tanks. The injected fluid may be a blend of water and one or more ketones by first blending in a blend tank (116), if desired. Alternatively, the injected fluid may be water for a period of time and then ketone for a period of time by bypassing the blend tank (116) and directly injecting the water and ketone. Of course, as should be understood, a single tank can be provided to supply both the water and the one or more ketones, or separate tanks can be provided, as illustrated in FIG. 1, to provide the various fluids to be injected.

Other additives, such as solvents, in addition to the one or more ketones may be included as desired. Each additive can be included in the ketone tank (114), or separate tanks, up to n number of tanks as illustrated in FIG. 1, can be included to add the various additives, water and one or more ketones.

Generally, the embodiments of the present invention relate to a class of chemicals that can alter the wettability of a rock in a subterranean formation. This class of chemicals is much safer from an environmental, health, and safety standpoint, as it is more environmentally benign, safer to humans to use, and has a lower risk of catastrophic incident during transport and deployment. The primary constituents of this class of chemicals is water and one or more ketones. The inherent health, safety and environment (HSE) advantages of water are evident from a transport, use, health, and environmental standpoint. Likewise, this class of chemicals, which are completely soluble in water and can be transported and used in a mixture comprising water to reduce HSE risks, are also a safer class of chemicals than other classes of chemicals such as aromatic solvents. The class of chemicals of the present invention includes ketones, which are generally accepted to be safer solvents than aromatic solvents from a health and safety standpoint based on available Material Safety Data Sheets (MSDS). While markedly different from traditional aromatic solvents, the Hansen Solubility Parameters (HSPs) are surprisingly favorable for ketones when injected into a system with both in situ hydrocarbons and water.

It is known that the wetting state of a formation rock influences the flow characteristics of various fluids in proximity to that rock. In porous media, wetting states are often classified in at least three classes, water wet, mixed wet, and oil wet. The wetting state, of course, is not as simple as these three apparently discrete classes would suggest, but rather it is a continuous and complex spectrum of states that evolve as a function of time, thermodynamic state, and the history of the surroundings. Wettability of a rock is not simply a state function influenced by the rock mineralogy, pore structure, and thermodynamic conditions, but rather it is strongly influenced by a myriad of factors, particularly related to the history, state, and chemistry of the fluids in proximity to the rock. For instance, wettability has been observed to be a strong function of the pH and ionic strength of a proximal aqueous phase as well as a strong function of the composition of a proximal hydrocarbon (particularly the fractional SARA distribution, acid number, and base number). As a function of the proximal fluids, wettability is known to evolve with time as a reservoir is altered (e.g., during production or stimulation). However, the fundamental controls behind wettability are still poorly understood, due to the complexity of this multivariate, ultra-fine-scale problem. It is hypothesized that the resin and asphaltene content of a proximal hydrocarbon system can strongly influence wettability. In particular, it is generally accepted that the higher the asphaltene content, the higher the propensity to tend toward an oil-wet state in a carbonate based mineralogical system. Even the definition of asphaltenes is disputed, but in general it is accepted that asphaltenes are components that are insoluble in n-pentane (or n-heptane) at a 40 to 1 alkane to crude oil ratio but soluble in toluene. Although asphaltenes encompass a variety of complex molecules, generally asphaltenes are either high in molecular weight, aromaticity, or polarity. Aromatic solvents, such as toulene, are common chemicals used in the lab for cleaning asphaltenes off of lab equipment and rock specimens; however, aromatic solvents are not the most environmentally friendly solvents or the safest chemicals from a health and safety standpoint for use outside of a controlled lab environment. In addition, aromatic solvents tend to have a relatively high boiling point (e.g., approximately 110-144° C. @ 101 KPa for toulene and xylene), which can make them difficult to separate from crude oil.

In experiments with these systems, it has been observed that a ketone coupled with water can effectively displace more oil than water alone. Although the fundamental chemistry is still poorly understood, it is assumed that the ketone, perhaps in conjunction with either the hydrocarbon or aqueous chemistry, is affecting either the asphaltenes or resins in the system, which may have previously influenced rock wettability. It is possible that the ketone is effectively solubilizing asphaltenes and allowing the aqueous chemistry to preferentially wet the rock surface, shifting wettability from a more oil-wet state to a more water-wet state in at least a portion of the rock.

Another advantage to the aforementioned chemical system is the fact that ketones, such as acetone, typically have a lower boiling point than aromatic solvents (i.e., ˜57° C. @ 101 kPa for acetone). This property, coupled with the fact that ketones, such as acetone, don't form azeotropes with water, yet are highly soluble in water, make them readily separated from both the produced aqueous and produced hydrocarbon streams.

Ketones are a polar organic compound comprising a non-terminal carbonyl, CO═O group. One such ketone is as acetone (CH3-CO—CH3). The general formula for ketones is: R1(CO) R2, where R1 and R2 may be the same or different and may be branched, and where the carbon number of R1 and R2 may be 1 to 5. While these compounds are occasionally used in conjunction with toulene in the lab to clean specimens and lab equipment, it is rare to see them used in isolation since alone they are not as effective as the aforementioned combination. Due to the limited appreciation of the effectiveness of this class of chemicals in conjunction with water in a subterranean hydrocarbon-aqueous system, this class of chemicals has not been previously proposed to be used to alter wettability in a subterranean formation.

The presently disclosed technology may be especially useful in ultra-tight formations, which are often stimulated with hydraulic fracturing techniques. This technology is a cost-effective way of permanently altering the wettability of at least a portion of the formation towards a more water-wet state. Altering the wettability may not only result in more favorable relative permeability curves for oil production, but it may also result in additional water imbibition and retention in the reservoir, particularly in the low permeability portions of an ultra-tight, fractured reservoir. This additional water retention will result in increased oil production under the same pressure drop, as every additional subterranean volume of water stored in the reservoir will equate approximately to an additional subterranean volume of oil produced under a given pressure drop.

Subterranean formations are located between overburden and underburden, which largely act as seals or flow inhibitors/barriers. The subterranean formation can, among other things, contain siliciclastics and carbonate rocks, clay, minerals, in situ hydrocarbons, and organic material, within the formation materials thereof. The formation materials included in the present technology are those found in geologic formations such as tight reservoirs. Such formation materials include, but are not limited to, formations of rock and shale, which include hydrocarbons interspersed amongst the inorganic components.

Compositions applying the present technology are fluids including water and one or more ketones. Other chemicals may be added, for instance surfactants or alcohols. In the fluids of the present technology, the concentration of the ketone is vital. Ultimately, the ketone concentration of the total injected fluid ranges from 0.01 mass % to 50 mass % and the concentration of water ranges from 50 mass % to 99.99 mass %. Mass percent is defined herein as the percentage of the mass of a substance (for example ketone or water) to the mass of the entire mixture.

However, the total volume of the fluid may be injected in multiple steps to obtain the preferred mass %. For instance, a volume of fluid with ketone concentrations greater than 0.1 mass % or even greater than 10 mass % may be injected followed by or preceded by a volume of fluid with a lower ketone concentration. It is also intended to be within the scope of the present invention to inject pure ketone for some period of time and then inject water for another period of time. In the end, it is preferred that the mass % be within the above-mentioned ranges, after the various injection steps are completed.

The ketone may be selected from one or more of Cyclohexanone, Butanone, Acetone, Isophorone, or Methylisobutylketone, In a preferred embodiment the ketone is acetone.

Two of the advantages of using acetone are that it is relatively cheap and it is typically less toxic than many other solvents and chemicals used in the oil industry. The fluid comprises at least 0.01% ketone by volume.

One method using the technology disclosed herein includes injecting a fluid comprising a ketone and water into a subterranean formation which includes hydrocarbons. In one embodiment, the fluid including a ketone and water is injected through a well into a subterranean formation containing hydrocarbons, the injectant is allowed to reside for a period of time in the subterranean formation, and oil is subsequently produced from the subterranean formation.

The injectant can be left to reside in the subterranean formation for at least 3 hours before additional injectant is added, further pumping begins, or the fluid is recovered In additional embodiments, the injectant is allowed to reside for 1 to 3 days, 2 to 3 weeks, or 1 to 2 months. The amount of time that the injectant resides in the subterranean formation will depend on a number of factors, including whether the formation is a conventional formation, a tight formation or an ultra-tight formation.

The injection process may be cyclic or continuous. If cyclic, cycles which include both the injection and production durations may last 1 week. In additional embodiments, cycles, which include both the injection and production durations may last 1-2 months or 1-2 years. In addition, cycles of ketone-containing fluid then ketone-free fluid may be used.

Preferably, the ketone concentration of the fluid to be injected is between 0.01 mass % and 50 mass % and the concentration of water is between 50% and 99.9 mass %; however, a volume of fluid with ketone concentrations greater than 0.01 mass % or even greater than 10 mass % may be injected followed by or preceded by a volume of fluid with lower ketone concentrations or with no ketone concentration.

The injection of the fluid and subsequent oil recovery may be in the same well or different wells.

The porosity of the reservoir is important to characterize the volume of liquid needed, location of the wells and recognition of the effects obtainable with the present method. The term porosity refers to the percentage of pore volume compared to the total bulk volume of a rock. A high porosity means that the rock can contain more oil per volume unit. The saturation levels of oil, gas, and water refer to the percentage of the pore volume that is occupied by oil or gas. An oil saturation level of 20% means that 20% of the pore volume is occupied by oil, while the rest is gas or water.

During oil extraction, the pore content may change due to production or other parameters affecting the reservoir. In the present method, the injectant is injected into a subterranean formation and resides in the pore space for a period of time, to change the wettability of a portion of the subterranean formation to a more water wet condition, thereby releasing oil from the pore spaces. The presently disclosed fluids result in additional water imbibition and retention in the reservoir. This additional water retention results in increased oil production under the same pressure drop, as every additional subterranean volume of water stored in the reservoir will equate approximately to an additional subterranean volume of oil produced under a given pressure drop.

In some instances, the chemical attractive forces between the reservoir rock or subterranean formation and the oil hinder the extraction of the oil from the reservoir. This characteristic is termed “wettability.” In one embodiment, the subterranean formation includes oil-wet or mixed-wet material types. Oil wet is used to characterize materials having a preference for being in contact with an oil phase rather than water or a gas phase. Oil-wet materials preferentially imbibe oil and hinder extraction. Water-wet materials prefer to be in contact with a water phase rather than an oil or gas phase and may have a thin film of water coating their surface. An intermediate to water-wet condition is more desirable than a strongly oil-wet condition for efficient oil extraction. Subterranean formations which include mixed-wet materials include materials with intermediate wetting characteristics (i.e., contact angles between the oil-water interface and the surface of the rock that are closer to 90 degrees than 0 degrees or 180 degrees. The compositions and methods of the present invention assist in converting an oil-wet, intermediate-wet, or mixed-wet material to a water-wet material, thereby reducing the oil's adherence to the subterranean formation or reservoir rock.

FIG. 2 illustrates the further characterization of the hydrocarbon bearing subterranean formation (104) of FIG. 1 in terms of wettability. Wettability is the tendency of one fluid (302) to spread on, or adhere to, a solid surface/phase (304) in the presence of other immiscible fluids. In other words, wettability refers to the interaction between fluid (302) and solid phases (304). In a reservoir rock or hydrocarbon-bearing subterranean formation, the fluid (302) can be water or oil or gas, and the solid phase is the rock mineral assemblage or substrate (304). Wettability is defined by the contact angle θ (306) between the fluid-fluid interface (302) and the solid phase (304). A “wetting phase” fluid preferentially wets the solid rock surface. A wetting phase fluid often has low mobility, since attractive forces between the rock and fluid draw the wetting phase fluid into small pores in the rock substrate (304).

Reservoir rock is typically water wet (308) if water preferentially wets the rock surface. The rock is water-wet when the angle θ (306) is less than 90 degrees. A nonwetting phase fluid does not preferentially wet the solid rock surface. Reservoir rock is oil-wet if oil preferentially wets the rock surfaces. The reservoir rock is oil wet (310) when the angle θ (306) is greater than 90 degrees. Intermediate wet is defined as when the angle θ (306) is 90 degrees.

Another manner of identifying the potential success of oil recovery from subterranean formations is to characterize the permeability characteristics of the formation. Permeability is a measurement of the resistance to fluid flow of a particular fluid through the reservoir, and is dependent on the structure, connectivity, and material properties of the pores in a subterranean formation. Permeability can differ in different directions, and in different regions.

FIG. 3 is an example of a tight to ultra-tight hydrocarbon bearing subterranean formation (104) as depicted in FIG. 1. A tight to ultra-tight formation is characterized in terms of permeability, or permeability scale (202). In a conventional formation (204), the pore throat sizes are relatively large, such that when the pores are highly interconnected (208) the formation is conducive to the flow of hydrocarbons. A conventional formation (204) will have a relatively high permeability as compared to tight (210) or ultra-tight (212) formations. Both tight and ultra-tight formations are also known as unconventional formations.

Permeability can be defined using Darcy's law and can often carry units of m², Darcy (D), or milliDarcys (mD). Generally a reservoir rock in a conventional formation (204) can have a permeability ranging from 1 mD to greater than 1,000 mD. A tight formation (210) often can have rock with typical permeability in the range of 1 μD to 1 mD, and an ultra-tight formation (212) can often have rock with typical permeability of 1 nD to 1 μD. Some reservoirs have regions of ultra-tight permeability, where the local permeability may be less than 1 μD, while the overall average permeability for the reservoir may be between 1 μD and 1 mD. Some reservoirs may have regions of ultra-tight or tight permeability with typical permeability of less than 1 mD in a majority of the formation but regions of the formation with high permeability greater than 1 mD and even greater than 1 D, particularly in the case of reservoirs with natural fractures. In one embodiment, the fluid is injected into a formation with at least 90% of the formation having an unstimulated well test permeability below 1 mD.

Fracturing techniques may be used to provide a means to increasing the injectivity of a formation when the reservoir has low permeability characteristics. Fracturing techniques may also be used as a means of injecting fluid when the reservoir has low permeability characteristics.

The present compositions and methods increase the ability to produce in situ hydrocarbons from a subterranean formation by altering the wettability of at least a portion of the subterranean formation, and thus the relative permeability, even when fracturing had been previously performed, or is simultaneously performed. Thus, the present methods increases the ability to extract in situ hydrocarbons before, simultaneously with, or after other methods of recovery are performed on a reservoir. More specifically, the presently disclosed fluids may be injected before, during, or after a hydraulic fracturing process, or even in alternating bouts of hydraulic fracturing treatment.

The injection pressure for injecting the fluids of the present invention is preferably above the initial reservoir pressure but is not required to be above the initial reservoir pressure.

FIG. 4 illustrates the influence zone (402) of an injected volume of fluid or fluids within a hydrocarbon bearing subterranean formation (404) under cyclic injection phases (I-III). The well (406) placed in a hydrocarbon-bearing subterranean formation (404) can be a single well, operational as both an injection and production well, or alternatively can consist of distinct injection and production wells. The well (406) may be conventional or directionally drilled, thereby reaching the formation (404). The formation (404) may be conventional or stimulated using conventional hydraulic fracturing methods or alternative fracturing methods, thereby creating fractures in the formation. During a cyclic injection process, the production of hydrocarbons is stimulated by injecting via pressure an injected volume of fluid (402), or series (cyclic) volumes of fluid (408 & 410), represented by the influence zone (402), said fluid including at least water (410) and ketone (408). The fluid thus injected (402) may be a blend of water (408) and ketone (410) or vice versa, in series.

The ketone may be at least partially separated from the produced oil and water streams and recycled. This recycling process may involve selling the ketone or using it in another process, reinjecting it in the same subterranean formation or injecting it in another subterranean formation.

Methods of Modeling a Subterranean Formation

The presently disclosed technology includes methods for modeling the injection of a fluid comprising a ketone and water into a subterranean formation containing hydrocarbons. Based on this model, operational parameters may be determined. Such parameters include, but are not limited to: injection volumes, ratios, temperatures, pressures, duration, frequency, production rates, timing of injection or production, and production pressures.

The model may be informed by rate flow meters, instrumentation to measure produced or injected volumes, pressure measurements, composition measurements, temperature measurements, and other measurements taken from a specific reservoir. A computer, specially programmed to account for injection of the fluid including water and a ketone, linked to one or more tangible data storage or transmission media (such as a hard drive or disk or a connection to the internet or network of computers combined with a remote data storage medium), and connected to or equipped to analyze the data obtained from the instrumentation measuring the physical and tangible characteristics of the reservoir (such as the physical parameters of reservoir itself or the physical parameters of the injection fluid and the production fluid). This specially programmed computer would practically apply the information to regulate the oil recovery process, including the injection of fluids, gases, or other chemicals into the subterranean formation, and the monitoring and physical management of the well or devices capturing the produced fluids and gases.

FIG. 5 is a comparison of simulated cumulative oil production showing a base case represented by primary depletion after standard hydraulic fracturing, compared to the cumulative production over time under the instant methods represented herein. It is anticipated that approximately a 10% uplift in performance will be observed with this single stimulation treatment using the methods described herein.

The invention being thus described, it will be obvious that the same may be varied in many ways. Such variations are not to be regarded as a departure from the spirit and scope of the invention, and all such modifications as would be obvious to one skilled in the art are intended to be included within the scope of the following claims. 

What is claimed is:
 1. A method of recovering in situ hydrocarbons from a subterranean formation containing in situ hydrocarbons, the method comprising the steps of: injecting a volume of fluid with composition comprising 0.01 mass % or more of at least one ketone and 50 mass % or more of water into an injection well completed in the subterranean formation; and producing at least a fraction of the injected volume of fluid and in situ hydrocarbons from the subterranean formation through a production well completed in the subterranean formation.
 2. The method of producing in situ hydrocarbons from a subterranean formation according to claim 1, said method further comprising the steps of: placing a well in a subterranean formation; and inducing a fracture in at least a portion of the subterranean formation, wherein the surface area of the induced fracture is at least 0.1 square meters.
 3. The method of producing in situ hydrocarbons from a subterranean formation according to claim 2, wherein said step of injecting occurs before, simultaneously with, or after said step of inducing a fracture in the subterranean formation.
 4. The method of producing in situ hydrocarbons from a subterranean formation according to claim 1, further comprising the step of permitting the injected volume of fluid to reside for a period of time in the subterranean formation before said at least a fraction of the injected volume of fluid and the in situ hydrocarbons are produced from the subterranean formation
 5. The method of producing in situ hydrocarbons from a subterranean formation according to claim 1, wherein the injected volume of fluid comprises water, at least one ketone, and at least one surfactant.
 6. The method of producing in situ hydrocarbons from a subterranean formation according to claim 1, wherein the at least one ketone is acetone.
 7. The method of producing in situ hydrocarbons from a subterranean formation according to claim 1, wherein the composition of the injected volume of fluid comprises at least 0.1 mass % ketone.
 8. The method of producing in situ hydrocarbons from a subterranean formation according to claim 1, wherein the composition of the injected volume of fluid comprises 0.5 mass % to 10 mass % ketone and 50 mass % to 90 mass % water.
 9. The method of producing in situ hydrocarbons from a subterranean formation according to claim 1, wherein the step of injecting is cyclic or continuous.
 10. The method of producing in situ hydrocarbons from a subterranean formation according to claim 1, wherein the injected volume of fluid is injected continuously into a first injection well in fluid communication with the subterranean formation and in situ hydrocarbons are produced from a second production well in fluid communication with the subterranean formation.
 11. The method of producing in situ hydrocarbons from a subterranean formation according to claim 1, further comprising the step of separating the at least one ketone from the produced injected volume of fluid and in situ hydrocarbons.
 12. The method of producing in situ hydrocarbons from a subterranean formation according to claim 11, further comprising the step of re-injecting the separated ketone into the subterranean formation.
 13. The method of producing in situ hydrocarbons from a subterranean formation according to claim 11, wherein the volume of fluid enters the subterranean formation in the liquid phase.
 14. An in situ hydrocarbon recovery system comprising: a well connected to a subterranean formation containing in situ hydrocarbons; an injection apparatus connected to said well; and at least one storage container in fluid communication with the injection apparatus, wherein said at least one storage container includes at least one ketone and wherein said at least one storage container includes water.
 15. The in situ hydrocarbon recovery system according to claim 14, wherein there are a plurality of storage containers, and at least one of said plurality of storage containers includes at least one ketone and at least one of said plurality of storage containers includes water.
 16. The in situ hydrocarbon recovery system according to claim 14, wherein said at least two storage containers include a fluid composition comprising 0.01 mass % or more of at least one ketone and 50 mass % or more of water.
 17. The in situ hydrocarbon recovery system according to claim 14, wherein said at least two storage containers include water, at least one ketone, and at least one surfactant.
 18. The in situ hydrocarbon recovery system according to claim 14, wherein the at least one ketone is acetone.
 19. The in situ hydrocarbon recovery system according to claim 14, further comprising a second well in fluid communication with the subterranean formation for recovering in situ hydrocarbons from the subterranean formation.
 20. A method of altering the wettability of a subterranean formation containing in situ hydrocarbons, the method comprising the steps of: injecting a volume of fluid with a composition comprising 0.01 mass % or more of at least one ketone and 50 mass % or more of water into an injection well completed in the subterranean formation, wherein the subterranean formation is comprised of at least 10 mass % carbonate rock, thereby contacting the carbonate rock of the subterranean formation with at least a fraction of the injected volume of fluid; and permitting the injected volume of fluid to reside for a period of time in the subterranean formation.
 21. The method of altering the wettability of a subterranean formation according to claim 20, wherein said step of injecting occurs before, simultaneously with, or after inducing a fracture with surface area greater than 0.1 square meter in the subterranean formation.
 22. The method of altering the wettability of a subterranean formation according to claim 20, wherein the composition of the injected volume of fluid comprises water, at least one ketone, and at least one surfactant.
 23. The method of altering the wettability of a subterranean formation according to claim 20, wherein the at least one ketone is acetone.
 24. The method of altering the wettability of a subterranean formation according to claim 20, wherein the composition of the injected volume of fluid comprises at least 0.1 mass % ketone.
 25. The method of altering the wettability of a subterranean formation according to claim 20, wherein the composition of the injected volume of fluid comprises 0.5 mass % to 10 mass % ketone and 50 mass % to 90 mass % water.
 26. The method of altering the wettability of a subterranean formation according to claim 20, wherein the step of injecting is cyclic or continuous.
 27. The method of altering the wettability of a subterranean formation according to claim 20, wherein said step of injecting a volume of fluid further comprises injecting the volume of fluid into the subterranean formation in the liquid phase.
 28. A method of recovering hydrocarbons from a subterranean formation containing in situ hydrocarbons, the method comprising the steps of: building a computational model to simulate injecting a ketone and water into a subterranean formation containing in situ hydrocarbons; making a determination on how to operate an oil recovery process from the subterranean formation based on said computational model; and recovering hydrocarbons from the subterranean formation.
 29. The method of recovering hydrocarbons from a subterranean formation according to claim 27, wherein the step of making a determination further comprises determining injection rates, injection temperatures, injection pressures, injection duration, injection frequency, production rates, production pressures, production duration, and/or production frequency based on said computational model. 